EXHIBIT 13
Selected Financial Data
amounts in thousands except per share data
YEAR ENDED DECEMBER 31
1993 1992 1991 1990 1989
Sales of electricity $129,861 $115,087 $104,155 $89,026 $43,010
Sales of steam 2,198 2,255 2,029 ---- ----
Other income 17,194 10,187 9,379 7,787 5,386
Expenses 87,995 76,797 80,697 81,248 35,345
Income before provision for
income taxes 61,258 50,732 34,866 15,565 13,051
Income before change in
accounting principle and
extraordinary item 43,074 38,810 26,582 12,043 10,336
Cumulative effect of change
in accounting principle 4,100 ---- ---- ---- ----
Extraordinary item ---- (4,991) ---- ---- ----
Preferred dividends 4,630 4,275 ---- ---- ----
Net income 47,174 33,819 26,582 12,043 10,336
Income per share before change
in accounting principle and
extraordinary item 1.00 .92 .75 .44 .38
Cumulative effect of change in
accounting principle .11 ---- ---- ---- ----
Extraordinary item per share ---- (.13) ---- ---- ----
Net income per share 1.11 .79 .75 .44 .38
Total assets 715,984 580,550 517,994 393,853 349,282
Total liabilities 425,393 336,272 298,146 331,134 305,265
Deferred income 20,288 21,164 22,015 2,926 1,854
Redeemable preferred stock 58,800 54,350 54,705 4,705 ----
Stockholders' equity 211,503 168,764 143,128 55,088 42,163
Common stock cash dividends ---- ---- ---- ---- ----
Management's Discussion and Analysis of
Financial Condition and Results of Operations
dollars and shares in thousands except per share data
The following is Management's discussion and analysis of certain
significant factors which have affected the Company's financial
condition and results of operations during the periods included
in the accompanying statements of operations.
General
For purposes of consistency in financial presentation, the Plants
comprising the Coso Project (including the Navy I, Navy II, and
BLM Plants) capacity factors are based upon a capacity amount of
88 gross MW ("GMW")/80 net MW ("NMW") for each plant. The Navy
I and Navy II Plants each consist of a set of three turbines
located at a plant site. The BLM Plant consists of two turbines
at one site ("BLM East") and one turbine at another site ("BLM
West"). In April 1990, the Company completed a retrofit of the
two turbines at BLM East and in July 1990 completed associated
retrofitting of the cooling towers to increase the aggregate
installed capacity of the BLM Plant to 88 GMW/80 NMW, effective
July 2, 1990. Each Plant possesses an operating margin which
periodically allows for production in excess of the amount listed
above. However, through 1990, the Navy I, Navy II and BLM Plant
capacity amounts were restricted by the then existing PURPA
80NMW cap. With the lifting of the PURPA 80NMW cap in 1991,
utilization of this operating margin can, at times, produce plant
capacity factors in excess of 100%. Utilization of this
operating margin is based upon a variety of factors and can be
expected to vary throughout the year under normal operating
conditions.
Results of Operations
Three Years Ended December 31, 1993, 1992 and 1991
Sales of electricity and steam increased to $132,059 in the year
ended December 31, 1993 from $117,342 in the year ended December
31, 1992, a 12.5% increase. This improvement was primarily due
to a 9.1% increase in Coso Project's electric kWh sales to
2,186.7 million kWh from 2,004.0 million kWh, and an increased
price per kWh in accordance with the SO4 agreements. The
increase in Coso Project kWh sales was primarily due to the
completion of new production wells. The increase in sales of
electricity and steam in 1992 to $117,342 from $106,184 in 1991
was primarily due to increasing electric kWh sales by 6.0% to
2,004.0 million kWh from 1,890.4 million kWh largely as a result
of the drilling of additional production wells, and the
aforementioned increase in price per kWh pursuant to the SO4
Agreements.
The following operating data includes the full capacity and
electricity production of the Coso Project only:
1993 1992 1991
Overall Capacity Factor 104.0% 95.1% 89.9%
kWh Produced 2,186,700,000 2,004,000,000 1,890,402,000
Installed Capacity NMW
(Average) 240 240 240
The overall Coso Plant capacity factor was 108.8% in the fourth
quarter of 1993 compared to 109.1%, 100.9% and 97.1% for the
third, second and first quarters of 1993, respectively. The Navy
I Plant capacity factor was 111.2% in 1993, compared to 99.8% and
98.5% in 1992 and 1991, respectively.
The Navy II Plant capacity factor was 102.6% in 1993 compared to
98.1% and 99.9% in 1992 and 1991, respectively. The BLM Plant
capacity factor was 98.1% in 1993 compared to 87.2% and 71.4% in
1992 and 1991, respectively. The BLM Plant, Navy I Plant and the
Navy II Plant were overhauled in conjunction with scheduled
warranty inspections in 1993, 1992 and 1991 respectively,
resulting in a temporary reduction of the plant capacity factor
of 3% in the specified year.
Electric sale price per kWh for the Coso Project varies
seasonally in accordance with the rate schedule included in the
SO4 Agreements. The price consists of an energy payment based
on the annualized contracted rate of 10.11 cents per kWh in 1993,
9.23 cents per kWh in 1992, and 8.58 cents per kWh in 1991, and
constant annual capacity payments of which the Company's share
was $5,400 to $5,800 per annum for each of the three power
plants. Capacity payments are significantly higher in the months
of June through September. Bonus payments are received monthly,
of which the Company's share was approximately $1,000 per annum
for each of the three power plants.
The Coso Project's average electricity prices per kWh in 1993,
1992 and 1991 were comprised of (in cents):
Energy Capacity & Bonus Total
Average fiscal 1993 10.11 1.93 12.04
Average fiscal 1992 9.23 2.10 11.33
Average fiscal 1991 8.58 2.24 10.82
The Desert Peak and Roosevelt Hot Springs facilities ran at or
near capacity levels for each of the past three years.
Steam sales from the Roosevelt Hot Springs field, which was
acquired in January, 1991, remained relatively unchanged at
$2,198, $2,255, and $2,077 in 1993, 1992, and 1991, respectively.
Electric sales from Desert Peak were $5,177, $5,347 and $3,976
for the years 1993, 1992, and 1991, respectively. Desert Peak
was acquired in March 1991 and, accordingly, reflects only nine
months sales in 1991.
Interest and other income increased in 1993 to $17,194 from
$10,187 in 1992 and from $9,379 in 1991. The increase reflects
higher average cash balances, interest income on notes receivable
from the Coso Joint Ventures and interest income on the Company's
share of the cash reserves established in the refinancing of the
Coso Project debt in December, 1992.
The Company's cost per kWh* was as follows (in cents):
1993 1992 1991
Plant operations (net of Company's
operator fees) 1.64 1.65 1.77
General and administration 1.03 1.04 1.11
Royalties .65 .61 .49
Depreciation and amortization 1.39 1.33 1.31
Interests, less amounts capitalized 1.82 1.17 2.16
TOTAL 6.53 5.80 6.84
*Cost per kWh includes electrical production from the Desert Peak facility and
the electrical production equivalent of the Company's share of geothermal steam
produced at the Roosevelt Hot Springs field, acquired in March and January
1991, respectively.
The Company's expenses* as a percentage of sales of electricity
and steam were as follows:
1993 1992 1991
Plant operations (net of Company's
operator fees) 15.8% 17.7% 18.8%
General and administration 10.0 11.1 11.7
Royalties 6.3 6.6 5.2
Depreciation and amortization 13.5 14.3 13.9
Interests, less amounts capitalized 17.7 12.7 23.0
TOTAL 63.3% 62.4% 72.6%
*Expenses as a percentage of electricity sales and steam sales include
electricity sales from the Desert Peak facility and steam sales from the
Roosevelt Hot Springs field, acquired in March and January 1991, respectively.
The Company's expenses, excluding interest, increased as a
general result of the greater electricity production of the Coso
Project. However, in 1993, plant operations and general and
administration costs per kWh decreased from 1992. In 1992, the
Company's total expenses, excluding interest, were proportionally
less than the increase in electricity production of the Coso
Project.
The cost of plant operations increased to $25,362 in 1993 from
$24,440 in 1992, an increase of 3.8%. The cost of plant
operations increased to $24,440 in 1992 from $23,525 in 1991, an
increase of 3.9%. General and administration costs remained
relatively unchanged at $13,158 in 1993 compared to $13,033 in
1992. General and administration costs increased to $13,033 in
1992 from $12,476 in 1991, a 4.5% increase. However, for 1993
and 1992 both plant operations and general and administration
costs per kWh continued to decrease due to a proportionally
greater increase in electrical production than plant operations
and general administration costs. Plant cost per kWh decreased
to 1.64 cents in 1993 from 1.65 cents in 1992 and 1.77 cents in
1991. General and administration cost per kWh decreased to 1.03
cents in 1993 from 1.04 cents in 1992 and 1.11 cents in 1991.
Royalty costs increased to $8,274 in 1993 from $7,710 in 1992,
an increase of 7.3%. Royalty costs increased to $7,710 in 1992
from $5,505 in 1991, an increase of 40.1%, due to higher
electrical sales and a contractually scheduled increase in the
1992 royalty rate for the second and third turbines of the Navy
I Plant. Overall, the royalty cost per kWh increased to 0.65
cents in 1993 from 0.61 cents in 1992 and 0.49 cents in 1991.
Depreciation and amortization expense increased to $17,812 in
1993 from $16,754 and $14,752 in 1992 and 1991, respectively, a
6.3% increase from 1992 to 1993, and a 13.6% increase from 1991
to 1992. Depreciation and amortization expense for 1993 was 1.39
cents per kWh compared to 1.33 cents in 1992 and 1.31 cents per
kWh in 1991. The increase in 1993 was due to additional
capitalized costs associated with the settlement of litigation
involving Mission Power Engineering Company ("MPE") and the
Mission Power Group, as well as additional wells and gathering
systems. The increase in per kWh cost in 1992 was due largely
to the costs of an increased number of production and injection
wells.
Interest expense, less amounts capitalized, increased to $23,389
in 1993 from $14,860 in 1992, an increase of 57.4%, or 1.82 cents
per kWh in 1993, compared to 1.17 cents in 1992. Net interest
expense decreased to $14,860 in 1992 from $24,439, or 2.16 cents
per kWh in 1991. Net interest expense in 1993 increased due
primarily to the Company's higher weighted average interest rate,
higher levels of indebtedness associated with the Coso Project
and the issuance of convertible subordinated debentures in June
1993. The short-term variable rate debt on the Coso Project was
refinanced in 1992 with longer-term fixed rate debt. The
weighted average interest rate on the Coso Project debt was 7.9%,
5.4%, and 8.5% in 1993, 1992, and 1991 respectively. Net
interest expense decreased in 1992 from 1991 as a result of low
interest rates associated with the Coso Project's then variable
rate debt.
The provision for income taxes increased to $18,184 in 1993 from
$11,922 and $8,284 in 1992 and 1991, respectively. The effective
tax rate was 29.7%, 23.5% and 23.8% in 1993, 1992, and 1991. The
increase in the 1993 effective tax rate was a result of adopting
Financial Accounting Standard 109 ("FAS 109").
Income before the provision for income taxes increased 21% to
$61,258 in 1993 from $50,732 in 1992. Net income after a
cumulative effect of a change in accounting principle was $47,174
and net income available to common shareholders was $42,544 or
$1.11 per common share for the year ended December 31, 1993.
This compares to net income of $33,819 after an extraordinary
item and net income available to common shareholders of $29,544
or $.79 per common share for the year ended December 31, 1992.
Net income before cumulative effect of a change in accounting
principle for the year ended December 31, 1993 was $43,074 or
$1.00 per common share versus net income before an extraordinary
item of $38,810 or $.92 per common share in 1992. In 1991,
income before the provision for income taxes was $34,866 and net
income available to common shareholders was $26,582, or $.75 per
share.
Earnings per share were favorably impacted in 1992 by the
Company's repurchase of common shares during 1992 at an average
price of approximately $12.00 per share. The Company purchased
common shares to be held as treasury stock which were reissued
upon the exercise of options and warrants.
Liquidity and Capital Resources
The Company's cash and short-term investments were $127,756 at December
31, 1993 as compared to $54,671 at December 31, 1992. In addition,
the Coso Project retained cash and investments on project control
accounts of which the Company's share was $14,943 and $8,848 at
December 31, 1993 and 1992, respectively. Distributions out of
the project control accounts are made monthly to the Company for
operation and maintenance and capital costs and semiannually to
each Coso Joint Venture partner for profit sharing under a
prescribed calculation subject to mutual agreement by the
partners. In addition to these liquid instruments, the Company
recorded separately restricted cash of $48,105 and $62,514 at
December 31, 1993 and 1992, respectively. The restricted cash
balance in 1993 was comprised primarily of the Company's
proportionate share of Coso Project cash reserves for debt
reserve funds and in 1992 included a contingency reserve fund,
both of which were established in conjunction with the Coso
Project's refinancing of its previous bank debt.
Accounts receivable normally represents two months of revenues,
and fluctuates with both production and price per kWh.
The balance due from/to the Coso Joint Ventures relates to
operations, maintenance, and management fees for managing the
Coso Project. This amount fluctuates based on the timing of
billings and incurrence of costs.
In December 1992, the Company refinanced the existing bank debt
of the Coso Project (see Note 5 of the Notes to the Consolidated
Financial Statements). Coso Funding Corp. ("Funding Corp."), a
single-purpose corporation, was formed to issue $560,245 of notes
for its own account and as an agent acting on behalf of Navy I,
BLM and Navy II Plants. The proceeds were used in part to
replace the outstanding Coso Project bank indebtedness and to
provide funding within the Coso Project for certain reserves.
As of December 31, 1993 and 1992 the Company's proportionate
share of the Coso Project loan was $246,880 and $263,604,
respectively.
The Funding Corp. notes have remaining terms of up to eight years
and different fixed interest rates for each tranche. The
underlying project loans have identical terms as the Coso Project
loans and are also non-recourse to the Company.
In connection with the Coso Project refinancing, the Company
purchased Community Energy Alternatives Incorporated's ("CEA")
interest in the Coso Project at the close of the Coso Project
refinancing. See Note 5 of the Notes to the Consolidated
Financial Statements.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries
of SCECorp., and the Coso Joint Ventures reached a final
settlement of all of their outstanding disputes and claims
relating to the construction of the Coso Project. As a result
of the various payments and releases involved in such settlement,
the Coso Joint Ventures agreed to make a net payment of $20,000
to MPE from the cash reserves of the Coso Project contingency
fund and MPE agreed to release its mechanics' liens on the Coso
Projects. After making the $20,000 payment, the remaining
balance of the Coso Project contingency fund (approximately
$49,300) was used to increase the Coso Project debt reserve fund
from approximately $43,000 to its maximum fully-funded
requirement of $67,900. The remaining $24,400 balance of the
contingency fund was retained within the Coso Project for future
capital expenditures and for Coso project debt service payments.
Since the Coso Project debt service reserve is fully funded in
advance, Coso Project cash flows otherwise intended to fund the
Coso Project debt service reserve funds, subject to satisfaction
of certain covenants and conditions contained in the Coso Joint
Ventures' refinancing documents, are available for distribution
to the Company in is proportionate share.
On May 3, 1993, the transmission line dispute was settled and the
transmission line deposit of approximately $7,700 was released
to the Company.
In June of 1993, the Company issued $100,000 principal amount of
5% convertible subordinated debentures (the "Convertible
Subordinated Debentures") due July 31, 2000. The Convertible
Subordinated Debentures are convertible into shares of the
Company's common stock at any time prior to redemption or
maturity at a conversion price of $22.50 per share, subject to
adjustment in certain circumstances. Interest on the Convertible
Subordinated Debentures is payable semi-annually in arrears on
July 31 and January 31 each year, commencing on July 31, 1993.
The Convertible Subordinated Debentures are redeemable for cash
at any time on or after July 31, 1996 at a redemption price of
(expressed in percentages of the principal amount) 102%, 101%,
100% and 100% in 1996, 1997, 1998 and 1999, respectively. The
Convertible Subordinated Debentures are an unsecured general
obligation of the Company and subordinated to all existing and
future senior indebtedness of the Company.
The Senior Notes, of which $35,730 aggregate principal amount are
currently outstanding, mature in March 1995 and bear interest at
the rate of 12% per annum, plus contingent interest, calculated
by reference to the Company's share of the cash flow from the
Coso Project through December 31, 1994. Simultaneous with the
closing of a proposed offering of Senior Discount Notes (see Note
16 of the Notes to the Consolidated Financial Statements), the
Company intends to use approximately $39,000 to defease and
provide for the repayment of the entire aggregate principal
amount of Senior Notes outstanding. The Senior Notes prohibit
the payment of cash dividends unless the Company has a net worth
of at least $50,000 after payment of such dividends, and
dividends do not exceed 50% of accumulated net income subsequent
to December 31, 1987. The Senior Notes also place restrictions
on capital expenditures not related to the Coso Project.
Proceeds and benefits from warrants and options for shares of
common stock exercised in 1993 and 1992 aggregated approximately
$1,400 and $8,065, respectively. In addition, in September 1993,
the Company acquired The Ben Holt Co. ("BHC"), a thirty person
engineering firm for a combination of cash and Company stock.
In connection with this transaction, 87 shares were issued having
an aggregate market value of $1,557.
The Company repurchased 157 common shares during 1993 for the
aggregate amount of $2,897. The Company purchased common stock
to be held as treasury stock in anticipation of their reissue
upon the exercise of options. The Company repurchased 565 shares
of common stock in 1992 at an aggregate amount of $4,887. The
shares were reissued during 1992 upon the exercise of stock
options.
On October 13,1992, the Company repurchased, and cancelled,
certain warrants exercisable for 1,025 shares of unregistered
common stock at $2.04 per share, for a purchase price of $9.16
per share, or approximately $9,389 in aggregate. Kiewit Energy
Company ("Kiewit Energy") simultaneously purchased and exercised
other warrants to purchase 600 shares of unregistered common
stock at $2.04 per share, providing the Company with proceeds of
$1,200. On October 27, 1992, the Company repurchased and
cancelled warrants exercisable for 250 shares of unregistered
common stock at $2.04 per share, for a purchase price of $9.316
per share, or $2,329 in aggregate.
On November 15, 1992, the Company called the Company's Series B
convertible preferred stock, no par value (the "Series B
preferred stock"), for conversion into common stock. Each share
of Series B preferred stock was converted into two shares of
common stock and, accordingly, the Company issued 954.9 shares
of common stock.
In 1991, the Company and Kiewit Energy signed a Stock Purchase
Agreement and related agreements (see Note 12 to the Consolidated
Financial Statements). In addition, in 1991 the Company issued
one thousand shares of its Series C redeemable preferred stock
to Kiewit Energy for $50,000 per share.
On March 31, 1993, the Company acquired leases from Unocal on
26,000 acres of geothermal properties at the Glass Mountain site
in Northern California which includes three successful production
wells.
The Company is actively engaged in the acquisition of, and is
seeking to develop, construct, own and operate power projects
utilizing geothermal and other technologies, both domestically
and internationally, the completion of any of which is subject
to substantial risk. The Company is currently pursuing a number
of international power project opportunities in countries where
private power generation programs have been initiated, including
the Philippines and Indonesia. Development can require the
Company to expend significant sums for preliminary engineering,
permitting, legal and other expenses in preparation for
competitive bids which the Company may not win or before it can
be determined whether a project is feasible, economically
attractive or financeable. Successful development is contingent
upon, among other things, negotiation of construction, fuel
supply and power sales contracts with other project participants
on terms satisfactory to the Company, and receipt of required
governmental permits and consents. Further, there can be no
assurance that the Company will obtain access to the substantial
debt and equity capital required for the acquisition or
development and construction of electric power projects. To the
extent the Company engages in international development efforts,
the financing and development of projects entails significant
political and financial risks (including, without limitation,
uncertainties associated with first time privatization efforts
in the countries involved, currency exchange rate fluctuations,
currency repatriation restrictions, political instability, civil
unrest and expropriation) and other structuring issues that have
the potential to cause substantial delays or that the Company may
not be fully capable of insuring against. There can be no
assurance that development efforts on any particular project, or
the Company's acquisition or development efforts generally, will
be successful.
In particular, the Company is developing a number of
international projects, for which it may have significant capital
requirements. In 1994, the Company intends to incur capital
expenditures in excess of $40,000 for international project
development. In addition to its international projects, the
Company plans to incur domestic geothermal capital expenditures
in the approximate aggregate amount of $30,000 in 1994. The
Company's planned capital spending includes, among other things,
its share of recurring Coso Project capital expenditures, as well
as development of the Newberry Project in the Pacific Northwest.
The Company is constructing the Yuma Project, a 50 MW natural gas
fired cogeneration project in Yuma, Arizona. Engineering and
equipment procurement commenced in 1993. Capital expenditures
of $10,000 are anticipated through the completion of the Yuma
Project by mid year 1994. The capital expenditures will be
funded from existing cash balances and the Company's operating
cash flows.
Inflation has not had a substantial impact on the Company's
operating revenues and costs. The Coso Project's energy payments
for electricity will continue to be based upon scheduled rate
increases through the initial ten-year period of each SO4
Agreement. Prior to the Coso Project refinancing, the Project
Loans relating to the Coso Project were generally for periods up
to twelve months at LIBOR plus a specified margin. Accordingly,
the interest rates on the loans varied and over the operating
period resulted in fluctuating interest payments. The refinanced
Coso Project debt has fixed interest rates.
Adoption of Financial Accounting Standard No. 109
On January 1, 1993, the Company adopted FAS 109. The adoption
of FAS 109 changes the Company's method of accounting for income
taxes from the deferred method as required by Accounting
Principles Board No. 11 to an asset and liability approach. Under
FAS 109, the net excess deferred tax liability as of January 1,
1993 was determined to be $4,100. This amount is reflected in
1993 income as the cumulative effect of a change in accounting
principle. It primarily represents the recognition of the
Company's tax credit carryforwards as a deferred tax asset.
There was no cash impact to the Company upon the required
adoption of FAS 109. Under FAS 109, the effective tax rate
utilized increased at the time of adoption as a result of the tax
credit carryforwards being recognized as an asset and unavailable
to reduce the current period's effective tax rate for computing
the Company's provision for income taxes. The effective tax rate
continues to be less than the statutory rate primarily due to the
depletion deduction and the generation of energy credits in 1993.
The significant components of the deferred tax liability are the
temporary differences between the financial reporting bases and
income tax bases of the power plant and the well and resource
development costs, and in addition, the offsetting benefits of
operating loss carryforwards and investment and geothermal energy
tax credits and alternative minimum tax carryforwards.
CONSOLIDATED BALANCE SHEETS
as of December 31, 1993 and December 31, 1992
dollars and shares in thousands, except per share amounts
ASSETS 1993 1992
Cash and investments $ 127,756 $ 54,671
Joint venture cash and investments (Note 5) 14,943 8,848
Restricted cash (Notes 4 and 5) 48,105 62,514
Accounts receivable 21,658 16,172
Transmission line deposit (Note 13) --- 7,684
Due from Joint Ventures 1,394 ---
Geothermal power plant and development costs,
net (Notes 4 and 5) 458,974 389,646
Equipment, net of accumulated depreciation of
$4,773 and $3,996 4,540 4,312
Notes receivable - Joint Ventures (Note 13) 11,280 9,997
Deferred charges and other assets 27,334 26,706
_________ _________
Total assets $ 715,984 $ 580,550
LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities:
Accounts payable $ 607 $ 3,146
Other accrued liabilities 19,866 18,111
Income taxes payable (Note 8) 4,000 ---
Project finance loans (Note 5) 246,880 263,604
Due to Joint Ventures --- 469
Senior notes (Note 6) 35,730 35,730
Convertible subordinated debentures (Note 7) 100,000 ---
Deferred income taxes 18,310 15,212
_________ _________
Total liabilities 425,393 336,272
Deferred income (Note 4) 20,288 21,164
Commitments and contingencies (Notes 3, 6, 9, 13 and 16)
Redeemable preferred stock (Note 10) 58,800 54,350
Stockholders' equity (Notes 11 and 12):
Preferred stock - authorized 2,000 shares,
no par value (Note 10) --- ---
Common stock - authorized 60,000 shares,
par value $0.0675 per share
issued and outstanding 35,446 and 35,258 shares 2,404 2,380
Additional paid in capital 100,965 97,977
Retained earnings 111,031 68,407
Treasury stock - 157 common shares at cost (2,897) ---
_________ _________
Total stockholders' equity 211,503 168,764
_________ _________
Total liabilities and
stockholders' equity $ 715,984 $ 580,550
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
for the three years ended December 31, 1993
dollars and shares in thousands, except per share amounts
1993 1992 1991
Revenue:
Sales of electricity and steam $132,059 $117,342 $106,184
Interest and other income 17,194 10,187 9,379
________ ________ ________
Total revenues 149,253 127,529 115,563
Cost and expenses:
Plant operations 25,362 24,440 23,525
General and administration 13,158 13,033 12,476
Royalties 8,274 7,710 5,505
Depreciation and amortization 17,812 16,754 14,752
Interest 30,205 20,459 29,814
Less interest capitalized (6,816) (5,599) (5,375)
________ ________ ________
Total expenses 87,995 76,797 80,697
Income before provision for income taxes 61,258 50,732 34,866
Provision for income taxes (Note 8) 18,184 11,922 8,284
Income before change in accounting principle
and extraordinary item 43,074 38,810 26,582
Cumulative effect of change in accounting
principle (Note 8) 4,100 --- ---
Extraordinary item (Note 15) --- (4,991) ---
Net income 47,174 33,819 26,582
Preferred dividends 4,630 4,275 ---
Net income available to common stockholders $42,544 $29,544 $26,582
Income per share before change in accounting
principle and extraordinary item $ 1.00 $ .92 $ .75
Cumulative effect of change in accounting
principle (Note 8) .11 --- ---
Extraordinary item (Note 15) --- (.13) ---
Net income per share $ 1.11 $ .79 $ .75
Average number of shares outstanding 38,485 37,495 35,471
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
for the three years ended December 31, 1993
dollars and shares in thousands
Outstanding Additional
Common Common Paid-In Retained Treasury
Shares Stock Capital Earnings Stock Total
Balance January 1, 1991 23,218 $ 1,567 $ 39,353 $ 14,168 $ --- $ 55,088
Exercise of stock options 2,329 157 14,959 --- --- 15,116
Sale and private placement
of common stock (Note 12) 6,505 439 43,237 --- --- 43,676
Exercise of warrants 660 45 2,897 --- --- 2,942
Issue costs of sale of preferred stock --- --- (276) --- --- (276)
Net income --- --- --- 26,582 --- 26,582
Balance December 31, 1991 32,712 2,208 100,170 40,750 --- 143,128
Exercise of stock options 1,544 67 2,764 --- --- 2,831
Exercise of warrants 612 41 1,206 --- --- 1,247
Issue costs on stock --- --- (96) --- --- (96)
Purchases/issuances of treasury stock
for exercise of options and warrants,
net of proceeds of $797 (565) --- (4,090) --- --- (4,090)
Preferred stock dividends, Series B & C,
including cash distributions of $134 --- --- --- (6,162) --- (6,162)
Retirement of warrants --- --- (11,716) --- --- (11,716)
Tax benefit from stock plan --- --- 3,420 --- --- 3,420
Net income before preferred dividends --- --- --- 33,819 --- 33,819
Conversion of preferred stock
to common stock 955 64 6,319 --- --- 6,383
Balance December 31, 1992 35,258 2,380 97,977 68,407 --- 168,764
Exercise of stock options 258 18 937 --- --- 955
Issuance of stock for purchase of
The Ben Holt Co. 87 6 1,551 --- --- 1,557
Purchase of treasury stock (157) --- --- --- (2,897) (2,897)
Preferred stock dividends, Series C,
including cash distributions of $100 --- --- --- (4,550) --- (4,550)
Tax benefit from stock plan --- --- 500 --- --- 500
Net income before preferred dividends --- --- --- 47,174 --- 47,174
Balance December 31, 1993 35,446 $ 2,404 $100,965 $111,031 $ (2,897) $211,503
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
for the three years ended December 31, 1993
dollars in thousands
1993 1992 1991
Cash flows from operating activities:
Net income $ 47,174 $33,819 $26,582
Adjustments to reconcile net cash flow from operating activities:
Depreciation and amortization 17,812 16,754 14,752
Amortization of deferred financing costs 1,013 967 1,054
Expense of previously deferred financing costs --- 3,895 ---
Provision for deferred income taxes 3,098 3,645 5,889
Other --- --- (639)
Changes in other items:
Accounts receivable (5,486) 1,279 (3,701)
Accounts payable and other accrued liabilities (784) (7,082) (10,890)
Deferred income (876) (851) (589)
Income tax payable 4,000 (1,202) 713
Other assets (177) 814 (2,157)
________ _______ _______
Net cash flows from operating activities 65,774 52,038 31,014
Cash flows from investing activities:
Capital expenditures relating to power plants (10,295) (6,711) (112)
Well and resource development expenditures for existing projects (16,565) (19,203) (20,564)
Acquisition of equipment (1,104) (1,093) (773)
Acquisition of Nevada and Utah properties --- --- (43,062)
Pacific Northwest, Nevada, and Utah exploration costs (19,060) (4,145) (3,866)
Yuma - construction in progress (40,167) (1,294) ---
Transmission line deposit 7,684 (118) (1,404)
Decrease (increase) in restricted cash 14,409 9,882 (2,217)
Decrease (increase) in other investments 941 (14,503) ---
________ ________ ________
Net cash flows from investing activities (64,157) (37,185) (71,998)
Cash flows from financing activities:
Proceeds from sale of common, treasury and preferred
stocks and exercise of warrants and options 2,912 8,065 111,458
Repayment of project finance loans --- (17,098) (10,100)
Repayment of project loans (16,724) (6,277) ---
Retirement of project finance loans --- (204,210) ---
Payment of other senior notes --- --- (6,000)
Proceeds from refinancing --- 269,881 2,400
Proceeds from issue of convertible subordinated debentures 100,000 --- ---
Increase in restricted cash related to the refinancing --- (65,670) ---
Net change in short-term bank loan --- --- (15,000)
Deferred charges relating to debt financing (2,582) (2,937) (58)
Decrease (increase) in amounts due from Joint Ventures (3,146) 6,198 (6,180)
Purchase of warrants --- (11,716) ---
Proceeds from pre-sale of steam --- --- 20,317
Purchase of treasury stock (2,897) (4,887) ---
________ ________ ________
Net cash flows from financing activities 77,563 (28,651) 96,837
Net increase (decrease) in cash and investments 79,180 (13,798) 55,853
Cash and investments at beginning of period 63,519 77,317 21,464
________ ________ ________
Cash and investments at end of period $142,699 $63,519 $77,317
Interest paid (net of amounts capitalized) $20,136 $19,237 $24,435
Income taxes paid $6,819 $4,129 $1,682
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
for the three years ended December 31, 1993
dollars and shares in thousands, except per share amounts
1. BUSINESS
California Energy Company, Inc. (the "Company") was formed in
1971. It is primarily engaged in the exploration for and
development of geothermal resources and conversion of such
resources into electrical power and steam for sale to electric
utilities, and the development of other environmentally
responsible forms of power generation.
The Company has organized several partnerships and Joint
Ventures (herein referred to as Coso Joint Ventures) in order
to develop geothermal energy at the China Lake Naval Air
Weapons Station, Coso Hot Springs, China Lake, California.
Collectively, the projects undertaken by these Coso Joint
Ventures are referred to as the Coso Project. The Company is
the operator and holds interests between 46.4% and 50% in the
Coso Joint Ventures after payout. Payout is achieved when a
Coso Joint Venture has returned the initial capital to the
Coso Joint Venturers. In addition, the Company is exploring
geothermal resources in Northern California, Washington and
Oregon (collectively the Pacific Northwest). In January 1991,
the Company acquired a power plant and an interest in steam
fields in Nevada and Utah (See Note 4 Nevada and Utah
Properties). In 1992, the Company entered into the natural
gas-fired electrical generation market through the purchase of
a development opportunity in Yuma, Arizona. Commercial
operation of the Yuma project will commence in 1994. In 1993,
the Company started developing a number of international power
project opportunities where private power generating programs
have been initiated, including the Philippines and Indonesia.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of
the Company, its wholly-owned subsidiaries, and its
proportionate share of the Coso Joint Ventures in which it has
invested. All significant inter-enterprise transactions and
accounts have been eliminated.
Investments and Restricted Cash
Investments other than restricted cash are primarily
commercial paper and money market securities. The restricted
cash balance includes such securities and mortgage backed
securities, and is mainly composed of the Coso Joint Ventures'
debt service reserve funds. The debt service reserve funds
are legally restricted to their use and require the
maintenance of specific minimum balances. The carrying amount
of the investments approximates the fair value based on quoted
market prices as provided by the financial institution which
holds the investments.
Well, Resource Development and Exploration Costs
The Company follows the full cost method of accounting for
costs incurred in connection with the exploration and
development of geothermal resources. All such costs, which
include dry hole costs and the cost of drilling and equipping
production wells, as well as directly attributable
administrative and interest costs, are capitalized and
amortized over their estimated useful lives when production
commences. The estimated useful lives of production wells are
ten years each; exploration costs and development costs, other
than production wells, are generally amortized over the
weighted average remaining term of the Company's power and
steam purchase contracts. For purposes of current period
visibility and disclosure, all such costs are identified in
the Consolidated Statements of Cash Flows as they are
incurred.
Deferred Well and Rework Costs
Well rework costs are deferred and amortized over the
estimated period between reworks. These deferred costs of
$1,305 and $1,592 at December 31, 1993 and 1992, respectively,
are included in other assets. Currently, both production and
injection well reworks are amortized over twelve months.
Fixed Assets and Depreciation
The cost of major additions and betterments are capitalized,
while replacements, maintenance, and repairs that do not
improve or extend the lives of the respective assets are
expensed.
Depreciation of the operating power plants is computed on the
straight-line method over the estimated useful lives resulting
in a composite rate of depreciation of approximately 2.67% per
annum. Depreciation of furniture, fixtures and equipment,
which are recorded at cost, is computed on the straight-line
method over the estimated useful lives of the related assets,
which range from three to ten years.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is
capitalized on the costs of the plants and geothermal resource
development to the extent incurred. Capitalized interest and
other deferred charges are amortized over the lives of the
related assets.
Deferred financing costs are amortized over the term of the
related financing. Loan fees are amortized using the implicit
interest method; other deferred financing costs are amortized
using the straight-line method. Accumulated amortization at
December 31, 1993 and 1992 was approximately $1,954 and $950,
respectively.
Revenue Recognition
Revenues are recorded based upon service rendered and
electricity and steam delivered to the end of the month.
Management Fee and Interest Revenue Recognition
The Company charges the Coso Joint Ventures management fees,
operator fees and interest on outstanding advances.
Recognition of fees and interest relating to power plants and
resource development of the Coso Joint Ventures in which the
Company has invested is deferred until each Coso Joint Venture
commences operations. Revenue previously deferred is
amortized over the lives of the related assets of the Coso
Joint Ventures as each Coso Joint Venture becomes operational.
Deferred Income Taxes
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for
Income Taxes". The adoption of FAS 109 changes the Company's
method of accounting for income taxes from the deferred method
as required by Accounting Principles Board Opinion No. 11 to
an asset and liability approach.
Net Income per Common Share
Earnings per common share are based on the weighted average
number of common and dilutive common equivalent shares
outstanding during the period computed using the treasury
stock method.
Cash Flows
The statement of cash flows classifies changes in cash
according to operating, investing, or financing activities.
Investing activities include capital expenditures incurred in
connection with the power plants, wells, resource development,
and exploration costs. The Company considers all investment
instruments purchased with a maturity of three months or less
to be cash equivalents. Restricted cash is not considered a
cash equivalent.
Reclassification
Certain amounts in the fiscal 1992 and 1991 financial
statements and supporting footnote disclosures have been
reclassified to conform to the fiscal 1993 presentation. Such
reclassification did not impact previously reported net income
or retained earnings.
3. INTEREST RATE SWAP AGREEMENTS
In January 1993, the Coso Joint Ventures entered into five
year deposit interest rate swap agreements which effectively
convert a notional deposit, the Company's portion of the
balance is $20,300 (restricted cash and investments), from a
variable rate to a fixed rate. The Company's proportion of
the deposit amount accretes annually to a maximum amount of
approximately $29,300 in 1996. Under the agreements, which
mature on January 11, 1998, the Coso Joint Ventures make semi-
annual payments to the counter party at variable rates based
on LIBOR, reset and compounded every three months, and in
return receive payments based on a fixed rate of 6.34%. The
effective LIBOR rate ranged from 3.25% to 3.375% during 1993
and was 3.375% at December 31, 1993. The counter party to
this agreement is a large multi-national financial
institution. The Company's proportionate share of the
carrying amount, representing accrued interest receivable, and
the fair value of the swap agreements are $277 and $1,281,
respectively. The fair value is based on quoted market prices
provided by the counter party to the swap.
In September 1993, the Company entered into a three year
deposit interest rate swap agreement, which effectively
converts a notional deposit balance of $75,000 from a variable
rate to a fixed rate. The Company makes semi-annual payments
to the counter party at effectively the LIBOR rate, reset
every six months, and in return receives payments based on a
fixed rate of 4.87%. The counter party to this agreement is
the same counter party to the Coso Joint Ventures. The
carrying amount is $286, representing accrued interest. The
fair value of the interest rate swap is currently negative in
the amount of $642 which is based on quoted market prices
provided by the counter party to the swap and assumes the
Company closes out the swap agreement prior to the stated
maturity.
4. PROPERTIES AND PLANTS
Properties and plants comprise the following at December 31:
1993 1992
Project costs:
Power plants $246,219 $235,924
Well and resource development 161,137 144,595
Total operating facilities 407,356 380,519
Less accumulated depreciation and amortization (67,813) (51,054)
Net operating facilities 339,543 329,465
Wells and resource development in progress 939 916
Total project costs 340,482 330,381
Pacific Northwest geothermal exploration costs 41,539 25,882
Nevada and Utah properties 35,492 32,089
Yuma - construction in progress 41,461 1,294
Total $458,974 $389,646
Operating Facilities
The Coso operating facilities comprise the Company's
proportionate share of the assets of three of its Joint
Ventures; Coso Finance Partners (Navy I Joint Venture), Coso
Energy Developers (BLM Joint Venture), and Coso Power
Developers (Navy II Joint Venture). With respect to the Coso
Project, distributions from its project accounts are made
semi-annually to each Coso Joint Venture partner for profit
sharing under a prescribed calculation subject to mutual
agreement by the partners and compliance with the Coso Joint
Ventures' financing documents. As of December 31, 1993,
payout had only been reached on Units 2 and 3 of the Navy I
power plant.
Navy I Plant
The Navy I plant consists of three turbines, of which one unit
commenced delivery of firm power in August 1987, and the
second and third units in December 1988. The 80NMW power
plant is located on land owned by and leased from the U.S.
Navy through to December 2009, with a 10 year extension at the
option of the Navy. Under terms of the Navy I Joint Venture,
profits and losses were allocated approximately 49% before
payout of Units 2 and 3 and approximately 46.4% thereafter to
the Company.
BLM Plant
The BLM plant consists of two turbines at one site (BLM East),
which commenced delivery of firm power in March and May,
1989, respectively, and one turbine at another site (BLM West)
which commenced delivery of firm power in August, 1989. The
BLM plant is situated on lands leased from the U.S. Bureau of
Land Management under a geothermal lease agreement that
extends until October 31, 2035. The lease may be extended to
2075 at the option of the BLM. Under the terms of the BLM
Joint Venture agreement, the Company's share of profits and
losses before and after payout is approximately 45% and 48%,
respectively. During 1990, the Company upgraded the cooling
tower and turbines to increase the plant's capacity to 80NMW
from the initial level of 70NMW.
Navy II Plant
The Navy II plant consists of three turbines, of which two
units commenced delivery of firm power in January 1990, and
the third in February 1990, respectively. The 80NMW power
plant is on the southern portion of the Navy lands. Under
terms of the Joint Venture, all profits, losses and capital
contributions for Navy II are divided equally by the two
partners.
Significant Customer
All of the Company's sales of electricity from the Coso
Project, which comprise approximately 94% of 1993 electricity
and steam revenues, are to Southern California Edison ("SCE")
and are under long-term power purchase contracts. Under the
terms of these contracts, SCE pays firm prices for the energy
portion of the contract. The energy payment escalates
pursuant to the contracts at an average rate of approximately
7.0% per year for the delivery of electricity for ten years,
commencing with the initial delivery of electricity at firm
power; thereafter, the energy payment adjusts to the actual
avoided energy cost experienced by SCE at that time. The
capacity payment, which initially represented approximately
25% of the Company's revenue, remains fixed during the entire
period of the contract. In addition, the Company is eligible
for bonus payments based on the amount by which the actual
output exceeds the contract capacity of each power plant.
Bonus payments aggregated $3,050, $3,257 and $2,635 in the
years ended December 31, 1993, 1992 and 1991.
The Company has three contracts for terms of 24, 30 and 20
years, expiring in 2011, 2019 and 2010, respectively.
Delivery of electricity by the Navy I Joint Venture, the BLM
Joint Venture, and Navy II Joint Venture commenced under those
contracts in 1987, 1989 and 1990, respectively.
See Note 13 for a description of litigation involving SCE.
Royalties
Royalties comprise the following for the years ended:
1993 1992 1991
Navy I, Unit I $1,556 $2,014 $1,787
Navy I, Units 2 and 3 2,924 2,628 1,160
BLM 1,868 1,268 1,033
Navy II 1,717 1,509 1,486
Other 209 291 39
Total $8,274 $7,710 $5,505
The amount of royalties paid by the Company to the U.S. Navy
to develop geothermal energy for Navy I, Unit 1 on the lands
owned by the Navy comprises (i) a fee payable during the term
of the contract based on the difference between the amounts
paid by the Navy to SCE for specified quantities of
electricity and the price as determined under the contract
(which currently approximates 71% of that paid by the Navy to
SCE), and (ii) $11,600 payable in December 2009. The $11,600
payment is secured by funds placed on deposit monthly, which
funds, plus accrued interest, will aggregate $11,600. The
monthly deposit is currently $23. As of December 31, 1993,
the balance of funds deposited approximated $1,283, which
amount is included in restricted cash and accrued liabilities.
Units 2 and 3 of Navy I and the Navy II power plants are on
Navy lands, on which the Navy receives a royalty based on
electric sales revenue at the initial rate of 4% escalating to
22% by the end of the contract in December 2019. The BLM is
paid a royalty of 10% of the value of steam produced by the
geothermal resource supplying the BLM Plant.
Pacific Northwest Geothermal Exploration Costs
In the Pacific Northwest, the Company has acquired leasehold
rights and has performed certain geological evaluations to
determine the resource potential of the underlying properties.
Recovery of those costs is ultimately dependent upon the
Company's ability to prove geothermal reserves and sell
geothermal steam, or to obtain financing, build power plants,
gain access to high voltage transmission lines, and sell the
resultant electricity at favorable prices or, sell its
leaseholds. In the opinion of management, the Company will be
able to realize its exploration costs through the generation
of electricity for sale.
Nevada and Utah Properties
On May 3, 1990, the Company entered into a definitive purchase
agreement with a subsidiary of Chevron Corporation ("Chevron")
for the acquisition of certain geothermal operations,
including interests in approximately 83,750 acres of
geothermal properties in Nevada and Utah, for an aggregate
purchase price of approximately $51,100. These property
interests consist largely of leasehold interests, including
properties leased from the BLM and from private landowners.
The property acquired from Chevron includes a 9MW power plant
at Desert Peak, Nevada ("Desert Peak"), and a 70% interest in
a steam field at Roosevelt Hot Springs, Utah ("Roosevelt Hot
Springs"). The facility at Desert Peak is currently selling
electricity to Sierra Pacific Power Company under a contract
that runs through 1995 and then may be extended on a year-to-
year basis as agreed by the parties. The price for
electricity under this contract is 6.5 cents per kWh,
comprising an energy payment of 2.0 cents per kWh (which is
adjustable pursuant to an inflation based index) and a
capacity payment of 4.5 cents per kWh. The Roosevelt Hot
Springs site has a contract to sell steam to a 25MW power
plant owned by Utah Power and Light Company ("UP&L") and to
dispose of the brine that is a by-product of the electricity
production process.
As part of the Nevada and Utah properties acquisition the
Company acquired leasehold interests in an aggregate of
approximately 20,000 acres at the Roosevelt Hot Springs site
in Utah and approximately 63,750 acres at four sites in
Nevada. The Roosevelt Hot Springs and Desert Peak properties
have been the subject of exploration and testing by Chevron
and its predecessors. Based on these tests and reports of
independent engineering companies, the Company believes that
there are significant geothermal resources available for
commercial development at these sites. Other tests conducted
by Chevron and its predecessors indicate that commercially
viable amounts of geothermal resources may underlie the other
Chevron properties.
The Company financed the acquisition of Roosevelt Hot Springs
through an equity offering, a $20,317 pre-sale of steam from
the Roosevelt Hot Springs field to the utility-owned power
plant located at the site, and seller financing. The
acquisition of Roosevelt Hot Springs and certain of the Nevada
properties closed on January 22, 1991 for an aggregate amount
of approximately $35,000. The remainder of the transaction
closed on March 28, 1991 and was financed with seller
financing and the proceeds of the sale of common stock to
Kiewit Energy Company ("Kiewit Energy"); see Note 12.
5. PROJECT LOANS
Project loans, which are non-recourse to the Company, comprise
the following at December 31:
1993 1992
Project loans with fixed interest rates (weighted average
interest rates of 8.04% and 7.88% at December 31, 1993 and
1992, respectively) with scheduled repayments through December 2001 $246,880 $263,604
The project loans are from Coso Funding Corp. ("Funding
Corp."). Funding Corp. is a single-purpose corporation formed
to issue notes for its own account and as an agent acting on
behalf of Navy I, BLM, and Navy II Joint Ventures,
collectively the "Coso Joint Ventures". Pursuant to separate
credit agreements executed between Funding Corp. and each Coso
Joint Venture on December 16, 1992, the proceeds from Funding
Corp.'s note offering were loaned to the Coso Joint Ventures.
The proceeds of $560,245 were used by the Coso Joint Ventures
to (i) purchase and retire project finance debt comprised of
the term loans and construction loans in the amount of
$424,500, (ii) fund contingency funds in the amount of
$68,400, (iii) fund debt service reserve funds in the amount
of $40,000, and (iv) finance $27,345 of capital expenditures
and transaction costs. The contingency fund and debt service
reserve fund were required by the project loan agreements.
The contingency fund represented the approximate maximum
amount, if any, which could theoretically have been payable by
the Coso Joint Ventures to third parties to discharge all
liens of record and other contract claims encumbering the Coso
Joint Ventures' plant at the time of the project loans (see
Note 13). The contingency fund was established in order to
obtain investment-grade ratings to facilitate the offer and
sale of the notes by Funding Corp., and such establishment did
not reflect the Coso Joint Ventures' view as to the merits or
likely disposition of such litigation or other contingencies.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries
of SCECorp., and the Coso Joint Ventures reached a final
settlement of all of their outstanding disputes and claims
relating to the construction of the Coso Project. As a result
of the various payments and releases involved in such
settlement, the Coso Joint Ventures agreed to make a net
payment of $20,000 to MPE from the cash reserves of the Coso
Project contingency fund and MPE agreed to release its
mechanics' liens on the Coso Project. After making the
$20,000 payment, the remaining balance of the Coso Project
contingency fund (approximately $49,300) was used to increase
the Coso Project debt reserve fund from approximately $43,000
to its maximum fully-funded requirement of $67,900. The
remaining $24,400 balance of contingency fund was retained
within the Coso Project for future capital expenditures and
for Coso Project debt service payments. Since the Coso
Project debt service reserve is fully funded in advance, Coso
Project cash flows otherwise intended to fund the Coso Project
debt service reserve fund, subject to satisfaction of certain
covenants and conditions contained in the Coso Joint Ventures'
refinancing documents, may be available for distribution to
the Company in its proportionate share.
The loans are collateralized by, among other things, the power
plants, geothermal resource, debt service reserve funds,
contingency funds, pledge of contracts, and an assignment of
all such Coso Joint Ventures' revenues which will be applied
against the payment of obligations of each Coso Joint Venture,
including the project loans. Each Coso Joint Venture's assets
will secure only its own project loan, and will not be cross-
collateralized with assets pledged under other Coso Joint
Venture's credit agreements. The project loans are non-
recourse to any partner in the Coso Joint Ventures and Funding
Corp. shall solely look to such Coso Joint Venture's pledged
assets for satisfaction of such project loans. However, the
loans are cross-collateralized by the available cash flow of
each Coso Joint Venture. Each Coso Joint Venture after
satisfying a series of its own obligations has agreed to
advance support loans (to the extent of available cash flow
and, under certain conditions, its debt service reserve funds)
in the event revenues from the supporting Coso Joint Ventures
are insufficient to meet scheduled principal and interest on
their separate project loans.
The annual repayments of the project loans for the years
beginning January 1, 1994 and thereafter are as follows:
1994 $ 27,599
1995 32,109
1996 38,826
1997 41,729
1998 38,912
Thereafter 67,705
________
$246,880
Based on quoted market rates of the Funding Corp. notes, the
fair value of the project loan was approximately $260,276 at
December 31, 1993.
In connection with the aforementioned refinancing, the Company
entered into an agreement with Community Energy Alternatives
Incorporated ("CEA") for the Company to purchase at the close
of the Coso Project refinancing CEA's interest in the Coso
Project. Until the close of the Coso Project refinancing, CEA
had been a partner in a partnership structure organized by the
Company's Joint Venture Partner in the BLM project. The
Company purchased the CEA interest under certain terms and
conditions which are designed to provide the Company with a
17% per annum return on the CEA interest purchase price of
$9,800. The Company's 17% per annum return is secured in part
by a pledge and assignment to the Company of certain cash
flows to be received by the Company's Coso Project Joint
Venture Partner (and certain affiliates) from Coso Project
distributions. The Company has granted its Coso Project Joint
Venture Partner the right to purchase the CEA interest for a
price which will provide the Company a 17% per annum return
for the duration the Company owns the CEA interest.
6. SENIOR NOTES
The Senior Notes are due in March 1995, and bear interest
at the rate of 12% per annum, plus 10% of the Company's
share of the cash flow from the Coso Project, commencing
July 1, 1989 and terminating December 31, 1994. The Senior
Notes prohibit the payment of cash dividends unless the
Company has a net worth of at least $50,000 after payment
of such dividends, and dividends do not exceed 50% of
accumulated net income subsequent to December 31, 1987.
The Senior Notes also place restrictions on capital
expenditures not related to the Coso Project. The fair
value of the Senior Notes approximates the carrying value.
7. CONVERTIBLE SUBORDINATED DEBENTURES
In June of 1993, the Company issued $100,000 principal amount
of 5% convertible subordinated debentures ("debentures") due
July 31, 2000. The debentures are convertible into shares of
the Company's common stock at any time prior to redemption or
maturity at a conversion price of $22.50 per share, subject to
adjustment in certain circumstances. Interest on the
debentures is payable semi-annually in arrears on July 31 and
January 31 of each year, commencing on July 31, 1993. The
debentures are redeemable for cash at any time on or after
July 31, 1996 at the option of the Company. The redemption
prices commencing in the twelve month period beginning July
31, 1996 (expressed in percentages of the principal amount)
are 102%, 101%, 100% and 100% in 1996, 1997, 1998 and 1999,
respectively. The debentures are unsecured general
obligations of the Company and subordinated to all existing
and future senior indebtness of the Company. The fair value
of the debentures as of December 31, 1993 was approximately
$103,250, which is based on quoted market rates.
8. INCOME TAXES
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 ("FAS 109"), "Accounting for
Income Taxes". The adoption of FAS 109 changes the Company's
method of accounting for income taxes from the deferred method
as required by Accounting Principles Board Opinion No. 11 to
an asset and liability approach. Under FAS 109, the net
excess deferred tax liability as of January 1, 1993 was
determined to be $4,100. This amount is reflected in 1993
income as the cumulative effect of a change in accounting
principle. It primarily represents the recognition of the
Company's tax credit carryforwards as a deferred tax asset.
There was no cash impact to the Company upon the required
adoption of FAS 109. Under FAS 109, the effective tax rate
increased to approximately 30% from 23.5% in 1992. This
increase was due to the Company's tax credit carryforward
being recognized as an asset and unavailable to reduce the
current period's effective tax rate for computing the
Company's provision for income taxes.
Provision for income tax is comprised of the following at December 31:
1993 1992 1991
Currently payable:
State $ 3,300 $ 2,300 $ 2,134
Federal 7,686 4,444 261
$10,986 $ 6,744 $ 2,395
Deferred:
State 385 1,607 929
Federal 6,813 2,038 4,960
7,198 3,645 5,889
Total after benefit of extraordinary item 18,184 10,389 8,284
Tax benefit attributable to
extraordinary item ---- 1,533 ----
Total before benefit of extraordinary item $18,184 $11,922 $ 8,284
The deferred expense is primarily temporary differences associated with
depreciation and amortization of certain assets.
A reconciliation of the federal statutory tax rate to the effective tax rate
applicable to income before provision for income taxes follows:
1993 1992 1991
Federal statutory rate 35.00% 34.00% 34.00%
Percentage depletion in excess of cost depletion (6.7) (6.81) (6.89)
Investment and energy tax credits (4.62) (10.52) (10.93)
State taxes, net of federal tax effect 3.90 5.83 6.32
Cumulative effect of change in federal tax rate 1.90 --- ---
Other .20 1.00 1.26
29.68% 23.50% 23.76%
Deferred tax liabilities (assets) are comprised of the following at December 31:
1993
Depreciation and amortization, net $111,117
Other 1,733
_______
112,850
Deferred income (2,415)
Loss carryforwards (39,529)
Energy and investment tax credits (40,106)
Alternative minimum tax credits (12,018)
Other (472)
_______
(94,540)
_______
Net deferred taxes $ 18,310
In 1992, the significant components of the deferred tax
liability were timing differences in the computation of
depreciation and amortization of the power plants and
exploration and development costs for financial reporting
purposes versus income tax purposes.
As of December 31, 1993, the Company has an unused net
operating loss (NOL) carryover of approximately $113,000 for
regular federal tax return purposes which expires primarily
between 2001 and 2007. In addition, the Company has unused
investment and geothermal energy tax credit carryforwards of
approximately $40,106 expiring between 2002 and 2008. The
Company also has approximately $12,018 of alternative minimum
tax credit carryforwards which have no expiration date.
9. COMMITMENTS
The Company's former office space lease, which requires annual
rental of $660 through April 1994, has been partially sublet
at annual rentals of $261 and remaining future rental costs
were previously provided for in a restructuring charge. The
Company also leases an aircraft under a lease that expires on
August 1, 1995, at an annual rental of approximately $464.
The aircraft has been subleased at an annual rental of
approximately $300. Rental expense for the aircraft,
vehicles, geothermal leases, and other equipment leases for
the years ended December 31, 1993, 1992 and 1991 was
approximately $1,143, $1,018 and $986 respectively.
Total projected lease commitments (net of sublease contracts)
at December 31, 1993, are as follows:
Year Ended
December 31, Amount
1994 $318
1995 186
1996 8
Total $512
10. PREFERRED STOCK
Series A:
On December 1, 1988, the Company distributed a dividend of one
preferred share purchase right ("right") for each outstanding
share of common stock. The rights are not exercisable until
ten days after a person or group acquires or has the right to
acquire, beneficial ownership of 20% or more of the Company's
common stock or announces a tender or exchange offer for 30%
or more of the Company's common stock. Each right entitles
the holder to purchase one one-hundredth of a share of Series
A junior preferred stock for $52. The rights may be redeemed
by the Board of Directors up to ten days after an event
triggering the distribution of certificates for the rights.
The rights plan was amended in February 1991 so that the
agreement with Kiewit Energy (see Note 12) would not trigger
the exercise of the rights. The rights will expire, unless
previously redeemed or exercised, on November 30, 1998. The
rights are automatically attached to, and trade with, each
share of common stock.
Series B:
On November 15, 1990, the Company sold 357.5 shares of
convertible preferred stock, Series B at $14 per share. Each
share of the convertible preferred stock was convertible into
two shares of common stock, and had a dividend rate of 15%
through November 15, 1992, 10% from November 16, 1992 to
November 15, 1994 and 5% from November 16, 1994 to November
15, 1996. The dividends were payable semi-annually in
convertible preferred stock, Series B.
On November 15, 1992, the Company called the preferred stock
for conversion into common stock. Each Series B preferred
stock was converted into two shares of common stock;
accordingly, the Company issued 954.9 shares of common stock.
Series C:
On November 19, 1991, the Company sold one thousand shares of
convertible preferred stock, Series C at $50,000 per share to
Kiewit Energy, in a private placement. Each share of the
Series C preferred stock is convertible at any time at $18.375
per common share into 2,721 shares of common stock subject to
customary adjustments. The Series C preferred stock has a
dividend rate of 8.125%, commencing March 15, 1992 through
conversion date or December 15, 2003. The dividends, which
are cumulative, are payable quarterly in convertible preferred
stock, Series C, through March 15, 1995 and in cash on
subsequent dividend dates.
The Company is obligated to redeem 20% of the outstanding
preferred stock, Series C each December 15, commencing 1999
through 2003 at a price per share equal to $50,000, plus
accrued and unpaid dividends.
At any time after December 15, 1994, upon 20 days written
notice, the Company may redeem all, or any portion consisting
of at least $5,000, of the preferred stock, Series C, then
outstanding, provided that the Company's common stock has
traded at or above 150% of the then effective conversion
price, for any 20 trading days out of 30 consecutive trading
days ending not more than five trading days prior to notice of
redemption.
The Company may also exchange the preferred stock, Series C,
in whole or part on any dividend date commencing December 15,
1994, for 9.5% convertible subordinated debentures of the
Company due 2003.
Each share of preferred stock, Series C shall be entitled to
the number of votes equal to $50,000 per share divided by the
then effective conversion price. If cash dividends are in
arrears six consecutive quarters, Kiewit Energy shall have the
exclusive right, voting separately as a class, to elect two
directors of the Company.
No cash dividends shall be paid or declared on the Company's
common stock unless all accumulated dividends on the Series C
preferred stock have been paid.
11. STOCK OPTIONS AND WARRANTS
The Company has issued various stock options and warrants. As
of December 31, 1993, a total of 8,953 shares are reserved for
stock options, of which 8,514 shares have been granted and
remain outstanding at prices of $3.00 to $19.00 per share.
Stock Options
The Company has stock option plans under which shares were
reserved for grant as incentive or non-qualified stock
options, as determined by the Board of Directors. As of
December 31, 1993, the total options granted for the non-1986
plan and the 1986 plan are 5,778 and 6,354, respectively. The
plans allow options to be granted at 85% of their fair market
value at the date of grant. Generally, options are issued at
100% of fair market value at the date of grant. Options
granted under the 1986 Plan become exercisable over a period
of three to five years and expire if not exercised within ten
years from the date of grant or, in some instances a lesser
term. Prior to the 1986 Plan, the Company granted 256 options
at fair market value at date of grant which had terms of ten
years and were exercisable at date of grant. In addition, the
Company had issued approximately 138 options to consultants on
terms similar to those issued under the 1986 Plan. The non-
1986 plan options are primarily options granted to Kiewit
Energy; see Note 12.
Transactions in Stock Options
OPTIONS OUTSTANDING
Shares Available for
Grant Under 1986 Option Price
Option Plan Shares Per Share Total
Balance January 1, 1991 72 3,361 $3.00 - $13.096 $ 12,658
Options granted (368) 8,268<F1> $8.063 - $14.875 89,193
Options terminated 304 (331) $3.00 - $9.708 (3,065)
Options exercised --- (2,328)<F1> $3.00 - $9.00 (15,116)
Additional shares reserved under 1986
Option Plan 1,230 --- --- ---
Balance, December 31, 1991 1,238 8,970<F1> $3.00 - $14.875 83,670
Options granted (551) 751 $11.90 - $15.938 11,262
Options terminated 129 (780) $3.00 - $11.625 (7,839)
Options exercised --- (1,544) $3.00 - $11.625 (7,072)
Balance December 31, 1992 816 7,397<F1> $3.00 - $15.938 80,021
Options granted (1,396) 1,396 $17.75 - $19.00 26,209
Options terminated 19 (20) $3.00 - $14.875 (114)
Options exercised --- (259) $3.00 - $14.875 (1,185)
Additional shares reserved under 1986
Option Plan 1,000 --- --- ---
Balance December 31, 1993 439 8,514<F1> $3.00 - $19.00 $104,931
Options which became exercisable during:
Year ended December 31, 1993 592 $3.00 - $19.00 $ 10,180
Year ended December 31, 1992 333 $3.00 - $15.938 $ 3,693
Year ended December 31, 1991 7,767<F1> $3.00 - $14.88 $ 79,890
Options exercisable at:
December 31, 1993 7,026<F1> $3.00 - $19.00 $ 78,644
December 31, 1992 6,708<F1> $3.00 - $15.938 $ 69,739
December 31, 1991 8,070<F1> $3.00 - $14.88 $ 73,481
<FN>
<F1> *Includes Kiewit Energy options. See Note 12.
Warrants
The Company has granted warrants in connection with various financing
activities to purchase shares of common stock
as follows:
WARRANTS OUTSTANDING
Warrant Shares Price per Share Total
Balance January 1, 1991 2,549 $2.04 - $6.67 $ 6,804
Warrants exercised (660) $2.04 - $6.67 (2,951)
Balance, December 31, 1991 1,889 $2.04 3,853
Warrants exercised (612) $2.04 (1,247)
Warrants repurchased (1,277) $2.04 (2,606)
Balance December 31, 1992 --- $ ---
On October 13, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 1,025 shares of unregistered common stock at
$2.04 per share, for a purchase price of $9.16 per share or $9,389 in
aggregate. Separately, Kiewit Energy simultaneously purchased and
exercised other warrants to purchase 600 shares of unregistered common
stock at $2.04 per share, providing the Company with proceeds of
$1,224.
On October 27, 1992, the Company repurchased, and cancelled, certain
warrants exercisable for 250 shares of unregistered common stock at
$2.04 per share, for a purchase price of $9.316 per share or $2,329
in aggregate.
12. COMMON STOCK SALES & RELATED OPTIONS
In January 1991, the Company sold 2,505 shares of unregistered common
stock at $6.75 per share for an aggregate total of $16,909. The funds
were used to repay a portion of the seller financing related to the
Company's acquisition of Chevron's interest in Roosevelt Hot Springs,
Utah.
The Company and Kiewit Energy signed a Stock Purchase Agreement and
related agreements, dated as of February 18, 1991. Kiewit Energy is
a subsidiary of Peter Kiewit Sons', Inc. of Omaha, Nebraska, a large
construction, mining, and telecommunications company with diversified
operations. Under the terms of the agreements, Kiewit Energy
purchased 4,000 shares of common stock at $7.25 per share and received
options to buy 3,000 shares at a price of $9 per share exercisable
over three years and an additional 3,000 shares at a price of $12 per
share exercisable over five years (subject to customary adjustments).
In connection with this initial stock purchase, the Company and Kiewit
Energy also entered into certain other agreements pursuant to which
(i) Kiewit Energy and its affiliates agreed not to acquire more than
34% of the outstanding common stock (the "Standstill Percentage") for
a five-year period, (ii) Kiewit Energy became entitled to nominate at
least three of the Company's directors, and (iii) the Company and
Kiewit Energy agreed to use their best efforts to negotiate and
execute a joint venture agreement relating to the development of
certain geothermal properties in Nevada and Utah.
On June 19, 1991, the board approved a number of amendments to the
Stock Purchase Agreement and the related agreements. Pursuant to
those amendments, the Company reacquired from Kiewit Energy the rights
to develop the Nevada and Utah properties, and Kiewit Energy agreed
to exercise options to acquire 1,500 shares of common stock at $9.00
per share, providing the Company with $13,500 in cash. The Company
also extended the term of the $9.00 and $12.00 options to seven years;
modified certain of the other terms of these options; granted to
Kiewit Energy an option to acquire an additional 1,000 shares of the
outstanding common stock at $11.625 per share (closing price for the
shares on the American Stock Exchange on June 18, 1991) for a ten year
term; and increased the Standstill Percentage from 34% to 49%.
On November 19, 1991, the Board approved the issuance by the Company
to Kiewit Energy of one thousand shares of Series C preferred stock
for $50,000, as described in Note 10 above. In connection with the
sale of the Series C preferred stock to Kiewit Energy, the Standstill
Agreement was amended so that the 49% Standstill Percentage
restriction would apply to voting stock rather than just common stock.
13. LITIGATION
Settlement of Contractor Claims
In June 1990, Mission Power Engineering Company ("MPE"), a subsidiary
of SCECorp. and the general contractor for eight of the nine
facilities at the Coso Project recorded mechanic's liens (the "Liens")
against two of the Coso Projects and filed suit to pursue claims for
amounts allegedly due from the Coso Joint Ventures in connection with
the turnkey contracts for the design and construction on eight of the
units. In July 1990, MPE, the Coso Joint Venture Partners and the
Company agreed to enter settlement discussions during which period the
suit was suspended. In January 1991, MPE terminated settlement
discussions and refiled its suit in the amount of approximately
$70,900 in contract claims. The Coso Joint Ventures counterclaimed
on January 10, 1991, for performance and equipment related and other
damages arising under the turnkey contracts.
On June 9, 1993, MPE and the Mission Power Group, subsidiaries of
SCECorp, and the Coso Joint Ventures and the Company announced that
the companies had reached a final settlement of all of their
outstanding disputes relating to the construction of and the filing
of mechanics' liens against the Coso Project.
Under the settlement agreement, MPE agreed to dismiss with prejudice
its $70,900 breach of contract suit against the Coso Joint Ventures
and the Coso Joint Ventures agreed to dismiss with prejudice their
counterclaims against MPE and related parties. As a result of the
various payments and releases involved in such settlement, the Coso
Joint Ventures agreed to make a net payment of $20,000 to MPE from the
cash reserves of the Coso Project Contingency Fund and MPE agreed to
release its mechanics' liens on the Coso Project.
Settlement of Transmission Line Disputes
In September 1990, the California Public Utilities Commission ("CPUC")
issued a decision which would fix at approximately $10,500 the Coso
Joint Ventures' maximum exposure for the cost of the construction of
a new 220kV electric transmission line ("Line") on the SCE
transmission system. The Coso Joint Ventures appealed the decision
of the CPUC to the Federal district court and intended to petition the
CPUC to reconsider its decision on the grounds that such Line is not
necessary. In a related proceeding involving the cost allocation for
existing and ancillary interconnection facilities, the CPUC ruled that
the Coso Joint Ventures' share would be approximately $7,000. The
Coso Joint Ventures appeal of such decision to the California Supreme
Court was denied in February 1993. In addition, SCE alleged certain
line losses that SCE deemed applicable to the existing 115kV line
utilized by two of the Coso Joint Ventures and deducted amounts from
revenues payable under the power purchase contracts. The Coso Joint
Ventures dispute SCE's allegations, methodology and alleged ability
to deduct amounts under the interconnection contracts and filed a
complaint alleging breach of contract in the California State Court.
On May 3, 1993, SCE and the Coso Joint Ventures agreed to settle the
transmission line loss contract dispute and certain related
interconnection disputes involving the Coso Project under a separate
agreement whereby, among other things, the parties made certain cash
payments to each other and agreed to certain interconnection cost and
historical line loss allocations and to the release to the Coso Joint
Ventures of certain funds previously deducted from project revenues
and held in escrow. The parties also agreed to jointly pursue
appropriate rate treatment by the CPUC of certain SCE financed
interconnection costs, including the one remaining cost allocation
issue between them in the amount of $5,900. As a result of the
various payments, allocations and releases involved in such partial
settlement, SCE released $15,500 of Coso Project funds (the Company's
share was approximately $7,800) held in escrow in respect of
interconnection costs (transmission line deposit) and the Partners of
Coso Joint Ventures' posted an irrevocable letter of credit to support
their contingent obligation of $5,900 on the cost allocation matter
to be jointly pursued with SCE at the CPUC.
Settlement of Anti-Trust Lawsuit
On January 31, 1991, the Company filed an antitrust lawsuit in San
Francisco Federal Court against SCECorp., its subsidiaries, (MPE,
Mission Power Group and SCE), Kidder-Peabody & Co., and others
alleging violations of the federal antitrust laws, unfair competition
and tortious interference. This lawsuit was settled in conjunction
with the transmission line disputes.
Settlement with Joint Venture Partner
The Company has served as managing partner, project manager and field
operator for the Coso Project since its inception. It has been plant
operator for the facilities since August 1988. In April 1990, the
Company's principal Coso Joint Venture partner (the "J.V. Partner")
served the Company and certain of the Company's subsidiaries with a
demand for arbitration arising out of disagreements concerning
primarily the operating budgets and the allocation to the Coso Joint
Ventures of certain expenses incurred by the Company.
On March 19, 1991, the Company and its J.V. Partner executed a
settlement agreement which resolved all their outstanding disputes.
The terms of the settlement provide that if the Coso Project performs
at capacity level in the future so that certain formula-based
contingencies related to the productivity of the power plants are
satisfied in any of the following eight years, then, out of the excess
cash flow generated from such performance levels, up to $1,400 may be
paid in each such year to the J.V. Partner by the Company. During
1992, the Company purchased the J.V. Partner's contingent payment for
$5,000; which will be amortized over the remaining seven years of the
agreement.
In return for the original settlement, the J.V. Partner agreed to the
conversion of all prior advances made by the Company on behalf of the
partnership into a Joint Venture note payable to the Company due on
or before March 19, 1999. The note bore interest at an adjustable
rate tied to LIBOR and was subordinated to the prior payment in full
of all the senior bank debt on the project as well as to the foregoing
contingent payments to the J.V. Partner. On December 16, 1992 the
Coso Joint Ventures paid $5,133 of their note payable plus accrued
interest to the Company. A new promissory note was then signed on
December 16, 1992 for the remaining principal balance. This note
bears a fixed interest rate of 12.5% and is payable on or before March
19, 2002. This note continues to be subordinated to the senior
project loan on the project. The fair value of this note approximates
the carrying value.
14. RELATED PARTY TRANSACTIONS
The Company charged and recognized a management fee and interest on
advances to its Coso Joint Ventures, which aggregated approximately
$5,354, $4,246 and $5,664 in the years ended December 31, 1993,
1992 and 1991.
15. EXTRAORDINARY ITEM
The refinancing of the Coso Joint Ventures' project financing debt in
1992 resulted in an extraordinary item in the amount of $4,991, after
the tax effect of $1,533. The extraordinary item represents the
unamortized portion of the deferred financing costs and related
repayment costs associated with the original Coso Joint Ventures'
project financing debt.
16. SUBSEQUENT EVENT
The Company is currently in the process of arranging a proposed
offering of $400,000 Senior Discount Notes ("Notes"). The interest
rate will be between approximately 9% and 10%, with cash interest
payment commencing in 1997. The Notes will be senior unsecured
obligations of the Company. The Company intends to use the proceeds
from the offering to: (i) fund equity commitments in, and the
construction costs of, geothermal power projects presently planned in
the Philippines and Indonesia, (ii) fund equity investments in, and
loans to, other potential international and domestic private power
projects and related facilities, (iii) for corporate or project
acquisitions permitted under the indenture, and (iv) for general
corporate purposes.
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Following is a summary of the Company's quarterly results of
operations for the years ended December 31, 1993 and December 31,
1992.
Three Months Ended *
March 31 June 30, September 30, December 31,
1993 1993 1993 1993
Revenue:
Sales of electricity and steam $ 27,617 $ 31,996 $ 41,433 $ 31,013
Other income 3,544 3,926 4,824 4,900
Total revenue 31,161 35,922 46,257 35,913
Total costs and expenses 20,314 21,833 22,087 23,761
Income before provision for income taxes
and change in accounting principle 10,847 14,089 24,170 12,152
Provision for income taxes 3,363 3,439 7,493 3,889
Net income before change in
accounting principle 7,484 10,650 16,677 8,263
Cumulative effect of change in accounting
principle 4,100 --- --- ---
Net income 11,584 10,650 16,677 8,263
Preferred dividends 1,107 1,143 1,179 1,201
Net income attributable to common shares $ 10,477 $ 9,507 $ 15,498 $ 7,062
Net income per share before change in
accounting principle $ .16 $ .25 $ .41 $ .18
Cumulative effect of change in accounting
principle .11 --- --- ---
Net income per share $ .27 $ .25 $ .41 $ .18
Three Months Ended*
March 31, June 30, September 30, December 31,
1992 1992 1992 1992
Revenue:
Sales of electricity and steam $ 24,147 $ 28,173 $ 37,977 $ 27,045
Other income 1,995 2,609 3,160 2,423
Total revenue 26,142 30,782 41,137 29,468
Total costs and expenses 18,541 18,779 20,583 18,894
Income before provisions for income taxes and
extraordinary item 7,601 12,003 20,554 10,574
Provision for income taxes 1,806 2,852 4,884 2,380
Net income before extraordinary item 5,795 9,151 15,670 8,194
Extraordinary item --- --- --- 4,991
Net income 5,795 9,151 15,670 3,203
Preferred dividends 1,020 1,056 1,089 1,110
Net income attributable to common shares $ 4,775 $ 8,095 $ 14,581 $ 2,093
Net income per share before
extraordinary item $ .13 $ .22 $ .39 $ .19
Extraordinary item --- --- --- (.13)
Net income per share $ .13 $ .22 $ .39 $ .06
*The Company's operations are seasonal in nature with a disproportionate
percentage of income earned in the second and third quarters.
Independent Auditors' Report
Board of Directors and Shareholders
California Energy Company, Inc.
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets
of California Energy Company, Inc. and subsidiaries as of
December 31, 1993 and 1992, and the related consolidated
statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the
Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
California Energy Company, Inc. and subsidiaries at December 31,
1993 and 1992 and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1993, in conformity with generally accepted accounting
principles.
As discussed in Note 8, the consolidated financial statements
give effect to the Company's adoption, effective January 1, 1993,
of Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes".
Deloitte & Touche
Omaha, Nebraska
February 24, 1994